Australia has launched its inaugural offshore wind auction, with Victoria seeking the first 2 gigawatts of a 9-gigawatt pipeline that must come online before the state’s remaining brown-coal generators retire in the early 2030s. The tender marks the first concrete procurement mechanism for a sector that has existed only as policy targets since 2022, but critical details – including revenue support structure, grid connection allocation, and how contracts will mesh with the National Electricity Market – remain unresolved weeks after the expression-of-interest window opened.
Victoria’s Offshore Wind Roadmap and the Auction’s Place in It
Victoria legislated offshore wind targets in 2022: 2 GW by 2032, 4 GW by 2035, and 9 GW by 2040. The federal government declared the Gippsland coast off Victoria’s southeast as the country’s first offshore wind zone in late 2022, followed by the Southern Ocean zone off Portland in 2023. Together these areas could host well over 20 GW of technical potential, but the 2 GW auction now live is the first time a state has moved from zone designation to actual capacity procurement.
The auction is being run by the Victorian government, not the Australian Energy Market Operator (AEMO) or the federal Clean Energy Regulator. That matters because Victoria’s transmission planner, VicGrid, is simultaneously redesigning how generation connects to the shared network – moving from a first-come, first-served model to a coordinated “renewable energy zone” framework where the planner identifies optimal connection points and builds shared transmission assets. Offshore wind projects that win this auction will be among the first large-scale generators to test that new regime.
Federal feasibility licences for the Gippsland zone were awarded in mid-2024 to a mix of international majors (Ørsted, Equinor, Oceanex) and local developers. Those licences grant seven years to conduct surveys and environmental assessments before a commercial licence can be sought. The state auction is effectively asking developers to commit to a delivery timeline – financial close and construction start – that compresses that seven-year window considerably if the 2032 target is to be met.
Supply Chain, Cost Trajectories, and the Global Benchmark
That points to a fundamental tension: global offshore wind costs have risen sharply since 2020. The UK’s Contracts for Difference (CfD) Allocation Round 5 in 2023 cleared at £44.47/MWh (2012 prices, roughly AUD 85/MWh today), but Round 6 in 2024 saw no offshore wind bids at all because the administrative strike price ceiling was deemed too low against inflated capital costs. European projects now regularly cite levelised costs of EUR 70-90/MWh (AUD 115-150/MWh) for projects reaching final investment decision in 2024-25.
If this trend holds, Victoria’s auction will need to offer revenue certainty well above historical Australian wholesale prices – which have averaged AUD 60-100/MWh in the National Electricity Market over the past five years – to attract bidders. The source notes contracts are “expected” to be integrated into the ESEM (Energy Security and Emergency Management framework), but whether that means a CfD-style top-up, a fixed-price power purchase agreement with a government counterparty, or another mechanism is unstated. Without clarity, developers cannot model bankable returns.
By comparison, the US Inflation Reduction Act provides a production tax credit of roughly USD 27.5/MWh (AUD 42/MWh) plus investment tax credit options, underpinning a pipeline now exceeding 50 GW in various stages. Australia has no equivalent federal production incentive for offshore wind; the Commonwealth’s Capacity Investment Scheme (CIS) has so far targeted onshore wind, solar, and storage. If Victoria’s auction relies solely on state-backed contracts, it will be a test of whether a single state’s balance sheet can underwrite multi-billion-dollar projects without federal risk-sharing.
Supply chain constraints compound the cost picture. Specialised installation vessels are booked years ahead globally. Australia has no domestic fabrication capacity for monopiles, transition pieces, or substations at utility scale. Developers will need to import nearly all major components, exposing projects to foreign exchange risk and shipping logistics that add 15-25% to capex versus European projects served by local yards. That is my own estimate based on general industry data for greenfield markets.
Grid Integration and the Coal Retirement Clock
The 2 GW target is not arbitrary. AEMO’s 2024 Integrated System Plan shows Victoria losing roughly 4.7 GW of brown-coal capacity by 2035 – Loy Yang A (2.2 GW) and Loy Yang B (1.0 GW) are both scheduled for closure by 2035, while Yallourn (1.5 GW) exits in 2028. Replacing that firm, synchronous generation with variable offshore wind requires simultaneous investment in transmission, storage, and system strength services.
VicGrid’s Gippsland Renewable Energy Zone design includes a new 500 kV double-circuit line from the Latrobe Valley to Melbourne, plus offshore collector substations and subsea cables. The total transmission bill for the first 2 GW is on the order of AUD 3-5 billion (approximate context from general REZ cost benchmarks), and the regulatory approval process under the National Electricity Rules typically takes 3-4 years from contingent project application to final determination. If the auction winners are announced in late 2025, financial close in 2026, and construction start in 2027, the transmission must be energised by 2030-31 to meet the 2032 target. That timeline has near-zero float.
System strength is a separate but related challenge. Brown-coal units provide inertia and fault current that offshore wind – connected via voltage-source converter HVDC or HVAC cables – does not inherently supply. AEMO has flagged that Victoria will need synchronous condensers or grid-forming inverters at scale by 2030. The auction rules could require winners to provide these services, adding further cost and technical complexity.
Who This Affects
- Utility planner: Must model 2 GW of offshore wind with uncertain capacity factors (likely 45-55% in Gippsland) and correlation to onshore wind/solar profiles, while solving for inertia and fault-level shortfalls in the 2030-35 window.
- Generation developer: Faces a compressed timeline to secure feasibility licence, transmission access, environmental approvals, and offtake contracts simultaneously – any single delay risks missing the 2032 target and forfeiting development rights.
- Policy analyst: Needs to evaluate whether a state-run auction can deliver lower system cost than a federal Capacity Investment Scheme round, and whether the “ESEM integration” language signals a new federal-state contracting model.
- Investor: Must price regulatory risk (auction rules unpublished), currency risk (capex in EUR/USD, revenue in AUD), and technology risk (first Australian projects, no local supply chain) against an unknown strike price or revenue floor.
What to Watch Next
- Publication of the final auction rules – specifically the revenue support mechanism, connection allocation process, and any local content or supply chain requirements – expected before bid submission deadline.
- VicGrid’s transmission investment test (RIT-T) outcome for the Gippsland REZ stage 1 assets, which will confirm cost allocation and earliest in-service dates.
- Federal commercial licence award decisions for Gippsland feasibility licence holders, which must precede any project’s financial close.
- First synchronous condenser or grid-forming battery commitment in Victoria’s 2025-26 transmission planning cycle, indicating whether system strength gaps are being addressed in parallel.
Bottom line: The auction is a necessary policy signal, but without published contract terms, aligned transmission delivery, and a credible cost-recovery framework, the 2 GW target risks becoming an aspirational milestone rather than a commissioned reality.
Read the full report at RenewEconomy
Original source: RenewEconomy (Australian clean energy news)
Note: facts and figures attributed above to RenewEconomy (Australian clean energy news) reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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